High-Speed, Multi-Power Submersible Pumps and Compressors

ABSTRACT

An apparatus, method and system for removing fluids from a well comprising a rotary pump for positioning within the well, the rotary pump including an inlet end and a discharge end, the rotary pump comprising at least one pump impeller intermediate the inlet end and discharge end, the at least one pump impeller rotating at a rate greater than 3600 rpm; a driver for driving the at least one pump impeller to a rate greater than 3600 rpm, the driver positioned within the wellbore and operatively connected to the rotary pump; a magnetic bearing system, the magnetic bearing system operatively connected to the rotary pump and/or driver; and a digital controller positioned within the wellbore to control the magnetic bearing system. A method for removing liquids from a well and an apparatus and method for producing gas from a wellbore or injecting a fluid into a wellbore are also provided.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional No. 61/897,035, filed Oct. 29, 2013, the entirety of which is incorporated herein by reference for all purposes.

FIELD

The present disclosure is directed generally to an apparatus and method for pumping fluids from a well. The present disclosure is also directed generally to an apparatus and method for producing gas from a wellbore or injecting a fluid into a wellbore.

BACKGROUND

Due to high reliability and relatively low complexity, gas lifting is the primary artificial lift method used in offshore oil wells. However, the reservoir draw-downs possible with gas lift are not as high as those that can be achieved with down hole pumps. The proper application of pumps can lower the abandonment pressure of wells, increasing reserves captured per well, and reducing the number of wells required to economically deplete an asset. Unfortunately, high-volume oilfield submersible pumping systems are plagued by various issues that reduce their applicability, particularly in high-cost offshore environments and horizontal directionally drilled wells.

Electric submersible pumps (ESPs) and hydraulic submersible pumps (HSPs) are the primary high-volume pumping options available to industry today. ESPs have reliability issues caused by induction motor, seal section, shaft, and power cable failures. The seal section is particularly troublesome, as it is designed to provide a physical barrier between the motor internals and the wellbore fluids. When the seal fails, wellbore fluids can reach the thrust bearings and/or motor, resulting in system failure. ESPs must be specially designed to handle produced gases, which further limits their use. ESPs are commonly installed as part of the tubing string, which means they require a costly pulling rig for installation and replacement.

HSPs are newer to the industry and have so far shown improved reliability. They can be installed through tubing and can better handle produced gases. However, HSPs require a high-pressure, high-volume source of power fluid to operate. This results in additional topside surface pumping and separation requirements. In addition offshore facilities typically have limited surface space, so most installations cannot support the surface equipment necessary to operate HSPs.

Motor shaft power output is defined as the product of rotation speed and torque. A high-speed motor therefore provides a means for obtaining more power from the same length of motor, or the same power from a shorter length. The output of a pump is defined in terms of its hydraulic power, which is the product of flow rate and lifting pressure. Centrifugal pump technology is characterized by the power output, which is proportional to the cube of the rotational speed. This relationship means that a relatively small increase in the rotational speed can give rise to a substantial power increase. For example, a 4″ single-stage centrifugal pump operating at 24,000 rpm can produce 6300 ft of head at ˜6000 bpd flow rate for 400 hp. About 300 typical ESP stages (4″, 6000 bpd rated, 3500 rpm) would be required to achieve this same performance with similar horsepower—but the height of the stacked stages would be near 100 ft!

Centrifugal pumps are frequently made with hundreds of impellers threaded on a common shaft, each impeller adding a little to the lifting pressure. Reducing the number of impellers by increasing the speed would therefore afford an improvement in reliability. As such, a high-speed motor and pump would present advantages in reliability due to reduced complexity, or alternatively yield a higher output for a similar size.

A large proportion of boreholes are deviated from vertical and horizontal. A much shorter motor/pump combination would also lead to a reduction in damage caused by mishandling and bending during deployment through the curved sections of the borehole.

In the case of electric motors, they are generally of the asynchronous, or induction, type. Since the transformer coupling to the rotor requires an alternating field in the rotor, the rotor must turn at a lower speed than synchronous speed. Electric submersible motors are made with two poles in order to achieve the maximum rotating speed from a standard 60 Hz utility supply. This speed is typically 3500 rpm, slightly less than the unattainable synchronous speed of 60 Hz×1 pole pair×60 s/min=3600 rpm.

It has become common to use variable speed drives to power these motors, rather than direct connection to the utility supply. Variable speed drives first convert utility AC power, typically at 60 Hz, to DC, and then by electronic switching convert the DC to a variable frequency alternating voltage. The use of a variable speed drive confers advantages during starting when it can limit the motor current to a safe level, and during production when it can be used to manage flow rates. Although variable speed drives, by creating an artificial supply of 70 Hz or more, can operate the motor at higher speed than when directly connected to the utility supply, this is a limited capability. Performance is generally limited up to 80 Hz or about 4500 rpm.

The mechanical seal section is required in a conventional ESP system to separate the pump environment from the motor environment, transfer power from the motor to the pump stages, allow positive differential pressure for the electric motor over the pump environment, handle expansion/contraction of dielectric oil, and provide a clean environment for the thrust bearing system. Thrust bearings are fluid-dynamic bearings that are located next to the seal section and absorb up- and down-thrust axial forces from the pump shaft. The thrust bearing is typically lubricated with a dielectric oil that is shared with the electric motor and seal section. As the mechanical seals inherently leak fluid into the wellbore, the system has to be designed for this loss of fluid and pressure maintenance or a separate line to supplement the lost dielectric fluid is required. When the ESP motor runs, it creates heat, causing the dielectric oil to expand. Some oil may be expelled into the wellbore through a check valve at the top of the mechanical seal section, never to be replaced. When the motor is stopped, it cools, decreasing the volume of the dielectric oil and reducing the pressure. A small amount of wellbore fluids (possibly with entrained solids) can be pulled into the motor during this thermal cycling process. Although the motor and thrust bearings are protected from encroaching wellbore fluid by the additional labyrinthine seal section next to the mechanical seal, excessive stops/starts or vibration will cause wellbore fluids to eventually reach the thrust bearing and foul it. The same fluids can electrically “short-out” the ESP motor. These failures will quickly reduce (or end) the run life of the ESP system. The existing thrust bearing system must be replaced in order to remove the seal section. Mechanical bearings (plain, rolling element, etc.) could be used in the ESP assembly, but they would require lubrication and could be fouled in a similar fashion as the existing thrust bearings if placed in the dielectric oil of the seal section. Hydrostatic or gas/air bearings could be used, but they would require a continuous, clean, pressurized fluid source—which would add more complexity and reliability concerns to the system with similar potential for fouling by the wellbore fluid.

As such, existing high-volume submersible pumps have drawbacks related to the AC electric motor, bearings and mechanical seal section reliability, and cost of deployment and replacement. They are also generally limited by line frequency, resulting in long pumps for providing the required head. This causes additional reliability issues since the bearings and seal must handle a long flexible rotor under varying loads. The overall length also makes it difficult to deploy the system through bends in deviated/horizontal wells. Therefore, what is needed are reliable, high-speed submersible pumps and compressors that overcome the shortcomings of existing technology, which are suitable for all types of wells, including vertical and horizontal wells.

SUMMARY

In one aspect, provided is an apparatus for removing fluids from a well. The apparatus includes a rotary pump for positioning within the well, the rotary pump including an inlet end and a discharge end, the rotary pump comprising at least one pump impeller intermediate the inlet end and discharge end, the at least one pump impeller rotating at a rate greater than about 3600 rpm; a driver for driving the at least one pump impeller to a rate greater than about 3600 rpm, the driver positioned within the wellbore and operatively connected to the rotary pump; a magnetic bearing system, the magnetic bearing system operatively connected to the rotary pump and/or driver, and a digital controller positioned within the wellbore to control the magnetic bearing system.

In some embodiments, the driver is selected from a gas-powered expander, an electric motor, a hydraulic motor and combinations thereof

In some embodiments, the driver is a gas-powered expander having an inlet and a discharge end, the gas-powered expander driven by high-pressure gas from a down hole gas production zone.

In some embodiments, the down hole gas production zone is regulated with a surface-controlled flow-control mechanism.

In some embodiments, the gas-powered expander is driven by injected gas lift gas.

In some embodiments, the injected gas lift gas enters the gas-powered expander inlet through a down hole gas lift mandrel.

In some embodiments, the rotational speed or rate of the gas-powered expander is varied by adjusting characteristics of the gas lift gas.

In some embodiments, the expanded gas is exhausted to a conduit to the surface.

In some embodiments, the apparatus further includes additional electronic control and/or monitoring components, and the additional electronic control and/or monitoring components and digital controller are cooled with gas at the discharge end of the gas-powered expander.

In some embodiments, the gas-powered expander operates at the same rotational speed or rate as the rotary pump impeller.

In some embodiments, the driver is an electric motor.

In some embodiments, the electric motor is a canned, seal-less motor.

In some embodiments, the electric motor is magnetically coupled to the rotary pump.

In some embodiments, the apparatus further includes a variable speed drive to control the speed or rate of the electric motor.

In some embodiments, the driver is a hydraulic motor, the hydraulic motor having a power fluid inlet and a power fluid discharge.

In some embodiments, the apparatus further includes a source of power fluid, the power fluid provided to the power fluid inlet from the surface through a conduit.

In some embodiments, the apparatus further includes a surface power fluid pump, wherein the speed or rate of the hydraulic motor is controlled by the output of the surface power fluid pump.

In some embodiments, the power fluid is provided to the hydraulic motor from a high-pressure liquid-producing zone.

In some embodiments, the high-pressure liquid-producing zone is regulated from a surface-controlled, flow-control mechanism.

In some embodiments, spent power fluid is discharged with the pump fluid.

In some embodiments, the apparatus further includes a generator for converting a portion of the rotational energy of the apparatus to electrical power.

In some embodiments, the magnetic bearing system is powered and controlled by the power produced by the generator.

In some embodiments, the magnetic bearing system is canned to prevent encroachment of wellbore fluids and improve reliability.

In some embodiments, the driver is connected to the rotary pump by a magnetic gear.

In some embodiments, the magnetic gear generates electricity for onboard use.

In some embodiments, the apparatus further includes onboard sensors, wherein at least a portion of the electricity generated powers the onboard sensors.

In some embodiments, the onboard sensors are used for closed-loop control of the rotary pump.

In some embodiments, the electricity generated powers wireless communications.

In some embodiments, the apparatus further includes an electric or fiber optic cable run in conjunction with a deployment device to relay sensor and control information to the surface.

In some embodiments, the apparatus further includes permanent sensors for incorporating into a completion to provide operational support.

In some embodiments, the apparatus further includes one or more fluid control devices for incorporating into a completion to provide an additional well control barrier.

In some embodiments, the apparatus further includes a Y-tool, the Y-tool when the rotary pump is placed in the well.

In some embodiments, the driver drives the rotary pump impeller to a rate greater than about 7200 rpm, or greater than about 10,000 rpm.

In another aspect, provided is a method of removing fluids from a well. The method includes the steps of installing an apparatus in a wellbore, the apparatus comprising a rotary pump having an inlet end and a discharge end, the rotary pump including at least one pump impeller intermediate the inlet end and discharge end; a driver for driving the at least one pump impeller, the driver positioned within the wellbore and operatively connected to the rotary pump; a magnetic bearing system, the magnetic bearing system operatively connected to the rotary pump and/or driver; and a digital controller positioned within the wellbore to control the magnetic bearing system; operating the apparatus at a rate greater than about 3600 rpm; and removing fluids from the well.

In yet another aspect, provided is an apparatus for producing fluids from a wellbore or injecting a fluid into a wellbore, the apparatus comprising a rotary compressor including an inlet end and a discharge end, the rotary compressor comprising at least one compressor stage intermediate the inlet end and discharge end, the at least one compressor stage rotating at a rate greater than 3600 rpm; a driver for driving the at least one compressor stage to a rate greater than about 3600 rpm, the driver positioned within the wellbore and operatively connected to the rotary compressor; a magnetic bearing system, the magnetic bearing system operatively connected to the high speed compressor and/or driver; and a digital controller positioned within the wellbore to control the magnetic bearing system.

In some embodiments, the driver is selected from a gas-powered expander, an electric motor, a hydraulic motor and combinations thereof

In some embodiments, the apparatus further includes a generator for converting a portion of the rotational energy of the apparatus to electrical power.

In some embodiments, the driver is connected to the rotary compressor by a magnetic gear, the magnetic gear generating electricity for onboard use.

In some embodiments, the driver is a gas-powered expander having an inlet and a discharge end, the gas-powered expander driven by high-pressure gas from a down hole gas production zone.

In some embodiments, the gas-powered expander is driven by injected gas lift gas.

In some embodiments, the injected gas lift gas enters the gas-powered expander inlet through a down hole gas lift mandrel.

In some embodiments, the rotational speed or rate of the gas-powered expander is varied by adjusting characteristics of the gas lift gas.

In some embodiments, the expanded gas is exhausted to a conduit to the surface.

In some embodiments, the driver is an electric motor.

In some embodiments, the electric motor is a canned, seal-less motor.

In some embodiments, the electric motor is magnetically coupled to the rotary compressor.

In some embodiments, the apparatus further includes a variable speed drive to control the speed or rate of the electric motor.

In some embodiments, the driver is a hydraulic motor, the hydraulic motor having a power fluid inlet and a power fluid discharge.

In some embodiments, the apparatus further includes a source of power fluid, the power fluid provided to the power fluid inlet from the surface through a conduit.

In some embodiments, the apparatus further includes a surface power fluid pump, wherein the speed or rate of the hydraulic motor is controlled by the output of the surface power fluid pump.

In some embodiments, the power fluid is provided to the hydraulic motor from a high-pressure liquid-producing zone.

In some embodiments, the high-pressure liquid-producing zone is regulated from a surface-controlled, flow-control mechanism.

In some embodiments, spent power fluid is discharged with the pump fluid.

In some embodiments, the apparatus further includes a generator for converting a portion of the rotational energy of the apparatus to electrical power.

In some embodiments, the magnetic bearing system is powered and controlled by the power produced by the generator.

In some embodiments, the magnetic bearing system is canned to prevent encroachment of wellbore fluids and improve reliability.

In some embodiments, the driver is connected to the rotary compressor by a magnetic gear.

In some embodiments, the magnetic gear generates electricity for onboard use.

In some embodiments, the apparatus further includes onboard sensors, wherein at least a portion of the electricity generated powers the onboard sensors.

In some embodiments, the produced fluid is gas.

In some embodiments, the driver drives the rotary compressor to a rate greater than about 10,000 rpm.

In some embodiments, the driver drives the rotary compressor to a rate greater than about 100,000 rpm.

In still yet another aspect, provided is a method of producing fluids from a wellbore or injecting a fluid into a wellbore, comprising installing an apparatus in a wellbore, the apparatus comprising a rotary compressor including an inlet end and a discharge end, the rotary compressor comprising at least one compressor stage intermediate the inlet end and discharge end, the at least one compressor stage rotating at a rate greater than about 3600 rpm; a driver for driving the at least one compressor stage, the driver positioned within the wellbore and operatively connected to one end of the rotary compressor; and a magnetic bearing system, the magnetic bearing system operatively connected to the rotary compressor and/or driver; and a digital controller positioned within the wellbore to control the magnetic bearing system; operating the apparatus at a rate greater than about 3600 rpm; and removing fluids from the well.

In an still further aspect, provided is a wellbore comprising a borehole in fluid communication with a subterranean reservoir; an apparatus for removing or injecting fluids, the apparatus installed within the wellbore and comprising i) a rotary pump or rotary compressor, the rotary pump or rotary compressor including an inlet end and a discharge end, and at least one pump impeller or at least one intermediate compressor stage rotating at a rate greater than about 3600 rpm; ii) a driver for driving the at least one pump impeller or at least one intermediate compressor stage to a rate greater than above about 3600 rpm, the driver positioned within the wellbore and operatively connected to the rotary pump or rotary compressor; iii) a magnetic bearing system, the magnetic bearing system operatively connected to the rotary pump or rotary compressor and/or driver; and iv) a digital controller positioned within the wellbore to control the magnetic bearing system.

In some embodiments, the driver is selected from a gas-powered expander, an electric motor, a hydraulic motor and combinations thereof.

In some embodiments, the apparatus comprises a rotary pump for the production of reservoir fluids.

In some embodiments, the apparatus comprises a rotary pump for the injection of fluids.

In some embodiments, the apparatus comprises a rotary pump for the separation of production fluids.

In some embodiments, the apparatus comprises a rotary compressor for enhancing fluid flow in a gas well.

In some embodiments, the apparatus comprises a rotary compressor for increasing the gas velocity in a production well.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 presents a schematic view of an illustrative, non-exclusive example of an apparatus for removing fluids from a well, according to the present disclosure.

FIG. 2 presents another schematic view of an illustrative, non-exclusive example of an apparatus for removing fluids from a well, according to the present disclosure.

FIG. 3 presents a schematic view of an illustrative, non-exclusive example of an apparatus for removing fluids from a well, according to the present disclosure.

FIG. 4 presents a detailed schematic view of an illustrative, non-exclusive example of a down hole expander pump for removing fluids from a well, according to the present disclosure.

FIG. 5 presents a detailed schematic view of an illustrative, non-exclusive example of a down hole high speed magnetic electric submersible pump (ESP) for removing fluids from a well, according to the present disclosure.

FIG. 6 presents a schematic view of an illustrative, non-exclusive example of an apparatus for producing gas from a wellbore or injecting a fluid into a wellbore, according to the present disclosure.

FIG. 7 presents another schematic view of an illustrative, non-exclusive example of an apparatus for producing gas from a wellbore or injecting a fluid into a wellbore, according to the present disclosure.

FIG. 8 presents a schematic view of an illustrative, non-exclusive example of an apparatus for producing gas from a wellbore or injecting a fluid into a wellbore, according to the present disclosure.

DETAILED DESCRIPTION

FIGS. 1-8 provide illustrative, non-exclusive examples of down hole high-speed submersible pumps having utility in connection with other wellbore-related methods and systems, according to the present disclosure of systems, and/or apparatus, and/or assemblies that may include, be associated with, be operatively attached to, and/or utilize such down hole high-speed submersible pumps. In FIGS. 1-8, like numerals denote like, or similar, structures and/or features; and each of the illustrated structures and/or features may not be discussed in detail herein with reference to FIGS. 1-8. Similarly, each structure and/or feature may not be explicitly labeled in FIGS. 1-8; and any structure and/or feature that is discussed herein with reference to FIGS. 1-8 may be utilized with any other structure and/or feature without departing from the scope of the present disclosure.

In general, structures and/or features that are or are likely to be included in a given embodiment are indicated in solid lines in FIGS. 1-8, while optional structures and/or features are indicated in broken lines. However, a given embodiment is not required to include all structures and/or features that are illustrated in solid lines therein, and any suitable number of such structures and/or features may be omitted from a given embodiment without departing from the scope of the present disclosure.

Disclosed herein is a centrifugal pumping apparatus that has three primary components: 1) high-speed pump stages, 2) a seal-less multi-power driver, and 3) high-reliability bearings. As used herein, “high-speed” refers to rotational speeds or rates greater than about 3,600 rpm, which is approximately the operational condition of common submersible AC induction or synchronous motors.

The high-speed pump stages greatly reduce the number of pump stages required to produce the same amount of discharge pressure as a standard ESP with a similar diameter. The high rotational speeds permit the pump to handle gas much more effectively than conventional ESPs. The reduction in pump stages also reduce the mass that the pump driver has to spin on the pump shaft. This reduces the operational requirements for shaft strength and driver power. A smaller driver and pump can provide a shorter overall pumping system, allowing much less costly rig-less, through-tubing deployments. These features also make it easier to deploy and function in directionally drilled horizontal wells.

The various forms disclosed herein benefit from having increased power density over conventional designs. By power density (or volumetric power density or volume specific power) is meant the amount of power, or time rate of energy transfer, per unit volume. Power density may be expressed in W/m³ or HP/ft³. As may be appreciated, power density can be an important consideration where space is constrained, such as in down-hole applications.

Conventional motors employed in ESP applications generally have a power density range of about 530 to about 2000 W/m³ (25 to 95 HP/ft³). The drivers contemplated herein advantageously have a power density of greater than about 2100 W/m³ (about 100 HP/ft³), or greater than about 3150 W/m³ (about 150 HP/ft³), or greater than about 4200 W/m³ (about 200 HP/ft³), or greater than about 6300 W/m³ (about 300 HP/ft³), or greater than about 8400 W/m³ (about 400 HP/ft³), or greater than about 10550 W/m³ (about 500 HP/ft³), or greater than about 12650 W/m³ (about 600 HP/ft³), or more. The drivers contemplated herein can yield downhole pumps, injectors, and the like, which possess over twice the available power of conventional ESPs at roughly ⅓ the service length.

FIG. 1 presents a schematic view of an illustrative, non-exclusive example of an apparatus 10 for removing fluids from a well W, according to the present disclosure. Apparatus 10 includes a rotary pump 12 for positioning within the well W. Rotary pump 12 includes an inlet end 14 and a discharge end 16. Rotary pump 12 further includes at least one pump impeller 15 intermediate inlet end 14 and discharge end 16.

Apparatus 10 further includes a driver for driving the at least one pump rotary pump impeller 15; the driver being positioned within the wellbore and operatively connected to rotary pump 12. In the embodiment depicted in FIG. 1, the driver comprises a gas-powered expander 18. As shown, gas-powered expander 18 has an inlet 20 and a discharge end 24. As may be appreciated by those skilled in the art, gas-powered expander 18 may be driven by high-pressure gas from a down hole gas production zone. In one embodiment, the down hole gas production zone may be regulated with a surface-controlled flow-control mechanism (not shown).

In another embodiment, gas-powered expander 18 may be driven by injected gas lift gas G. The injected gas lift gas G enters the gas-powered expander inlet through a down hole gas lift mandrel 22. As may be appreciated, the rotational speed or rate of gas-powered expander 18 may be varied by adjusting the characteristics of the gas lift gas G. In one embodiment, expanded gas is exhausted to the pump discharge 16. In another embodiment, the expanded gas is exhausted to a conduit (not shown) to the surface.

The expander blades may be designed to match the design speed or rate of the pump stages of rotary pump 12, or an integral gear, including a magnetic gear, can reduce the expander speed or rate to an appropriate pump speed. The magnetic gear can also incorporate a generator to produce electrical power for onboard uses. As may be appreciated, the use of an expander driver eliminates the problematic seal section. The expander-driven system may be deployed/retrieved with cable or coiled tubing.

As shown in FIG. 1, apparatus 10 further includes a magnetic bearing system 26. As may be appreciated by those skilled in the art, magnetic bearings can provide support for any ferromagnetic body without mechanical contact. Two basic magnetic bearing types exist: active magnetic bearings and passive magnetic bearings. With passive magnetic bearings, the bearing forces result from pairs of permanent magnets with opposing field directions producing mutual repulsion. Although this kind of contact-free support is simple, there are two drawbacks when compared with an active magnetic bearing. First, a complete six degree of freedom support of a rigid body by uncontrolled ferromagnetic forces is difficult to achieve and second, the bearing characteristics of passive magnetic bearings cannot be changed easily during operation, as is the case with active magnetic bearings. However, advances are being made with passive magnetic bearings. From a purely functional standpoint, a passive system could perform the bearing function without the need for input power, sensors, or a control system. A prototype passive bearing was recently tested to 1000 rpm by Lawrence Livermore National Laboratory and Arnold Magnetic Technologies, and higher speed testing was planned.

As may then be appreciated, the advantages of magnetic bearing system 26 compared with traditional solutions include the absence of mechanical wear and friction, lubricant-free operation and therefore suitability for severe environments, active vibration control and unbalance compensation.

Over the past few decades active magnetic bearings have been making inroads to the rotating equipment industry. Although passive magnetic bearings can be sealed or canned, they cannot be controlled during operation to adapt to changing bearing loads and thus are not seen to be a reliable solution. Active magnetic bearings are considered to be the optimal solution that can provide the necessary reliability while allowing for a seal-less, high-speed, high power density design. One issue in trying to deploy active magnetic bearings downhole is that the bearing control system must be within approximately 100 m of the bearings due to time delay in control communications. Thus, the magnetic bearing control system contemplated herein is small enough to fit within the wellbore allowing fluid flow around it, and can withstand the high temperature and hostile environment deep in the well.

Magnetic bearing system 26 may be operatively connected to rotary pump 12 and/or gas-powered expander 18. In one embodiment, magnetic bearing system 26 is canned to prevent encroachment of wellbore fluids and improve reliability.

In one embodiment, apparatus 10 includes magnetic bearing electronic controls 28, comprising a digital controller, and may also include subsurface monitoring components 30. In one form, the digital controller of magnetic bearing electronic controls 28 is positioned within the wellbore to control the magnetic bearing system. In one embodiment, electronic controls 28 and/or subsurface monitoring components 30 are cooled with gas at the discharge end of gas-powered expander 20. To power electronic components, a generator 32 for converting a portion of the rotational energy of apparatus 10 to electrical power may be provided. In one embodiment, magnetic bearing system 26 is powered and controlled by the power produced by generator 32.

In one embodiment, gas-powered expander 18 operates at the same rotational speed or rate as rotary pump 12.

Referring now to FIG. 2, a schematic view of another illustrative, non-exclusive example of an apparatus 100 for removing fluids from a well W, according to the present disclosure. Apparatus 100 includes a rotary pump 112 for positioning within the well W. Rotary pump 112 includes an inlet end 114 and a discharge end 116. Rotary pump 112 further includes at least one pump impeller 115 intermediate inlet end 114 and discharge end 116.

In the embodiment depicted in FIG. 2, the driver for driving the at least one pump rotary pump impeller 115 comprises an electric motor 118. As shown, electric motor 118 has a first end 120 and a second end 122. Electric motor 118 may be a high speed electric motor. In one embodiment, electric motor 118 may be a canned, seal-less motor. Advantageously, electric motor 118 may be magnetically coupled to rotary pump 112 using a magnetic coupler 120. As may be appreciated, electric motor 118 may also include a variable speed drive (not shown) to control the speed or rate of electric motor 118.

In one embodiment, electric motor 118 may be a brushless DC motor, an AC induction motor, or a permanent magnet motor. As may be appreciated, these types of motors can be canned to protect the motor windings from well fluids. Electric motor 118 can permit pump installations in areas that did not have gas available for an expander-driven version. It also allows rotary pump 112 to be set deeper than the deepest available gas injection point. The electric motor-driven system may be deployed/retrieved with an electric cable or coiled tubing with an internal electric cable.

As shown in FIG. 2, apparatus 100 further includes a magnetic bearing system 126. Magnetic bearing system 126 may be operatively connected to rotary pump 112 and/or electric motor 118. In one embodiment, magnetic bearing system 126 is canned to prevent encroachment of wellbore fluids and improve reliability.

In one embodiment, apparatus 100 includes magnetic bearing electronic controls 128, comprising a digital controller, and may also include subsurface monitoring components 130. In one form, the digital controller of magnetic bearing electronic controls 128 is positioned within the wellbore to control the magnetic bearing system. To power electronic components, a generator 132 for converting a portion of the rotational energy of apparatus 100 to electrical power may be provided. In one embodiment, magnetic bearing system 126 is powered and controlled by the power produced by generator 132.

Referring now to FIG. 3, a schematic view of another illustrative, non-exclusive example of an apparatus 200 for removing fluids from a well W, according to the present disclosure. Apparatus 200 includes a rotary pump 212 for positioning within the well W. Rotary pump 212 includes an inlet end 214 and a discharge end 216. Rotary pump 212 further includes at least one pump impeller 215 intermediate inlet end 214 and discharge end 216.

In the embodiment depicted in FIG. 3, the driver for driving the at least one pump rotary pump impeller 215 comprises a hydraulic motor 218, the hydraulic motor having a power fluid inlet 220 and a power fluid discharge 222. Hydraulic motor 218, has a source of power fluid D (not shown), the power fluid D provided to the power fluid inlet 220 from the surface S through conduit 224. In one embodiment, a surface power fluid pump 250 is employed, with the speed or rate of hydraulic motor 218 controlled by the output of power fluid pump 250.

Alternatively, power fluid D may be provided to hydraulic motor 218 from a high-pressure liquid-producing zone, as those skilled in the art will plainly understand. In such cases, the high-pressure liquid-producing zone can be regulated from a surface-controlled, flow-control mechanism. In one embodiment, the spent power fluid may be discharged with the pump fluid.

Hydraulic motor 218 may be a bent-axis or inline piston motor, a screw turbine, Frances turbine, Pelton wheel or other type of impulse or reaction turbine. The power fluid characteristics and operational speed may be optimized to reduce topside pumping and separation spatial requirements. These requirements could be further reduced by combining the pumping operation with gas lifting in the same well. Likewise, a gas lift expander drive could also be combined with the hydraulic drive to use the combination of both fluids to drive the rotary pump 212. Hydraulic motor 218 may employ a labyrinth or lip seal to separate fluids. The system of FIG. 3 may be deployed or retrieved with coiled tubing which could also serve as the power fluid conduit.

As shown in FIG. 3, apparatus 200 further includes a magnetic bearing system 226. Magnetic bearing system 226 may be operatively connected to rotary pump 212 and/or hydraulic motor 218. In one embodiment, magnetic bearing system 226 is canned to prevent encroachment of wellbore fluids and improve reliability.

In one embodiment, apparatus 200 includes magnetic bearing electronic controls 228, comprising a digital controller, and may also include subsurface monitoring components 230. In one form, the digital controller of magnetic bearing electronic controls 228 is positioned within the wellbore to control the magnetic bearing system. To power electronic components, a generator 232 for converting a portion of the rotational energy of apparatus 200 to electrical power may be provided. In one embodiment, magnetic bearing system 226 is powered and controlled by the power produced by generator 232.

Referring now to FIG. 4, a schematic view of an illustrative, non-exclusive example of an apparatus 300 for removing fluids from a well W is shown. As is conventional, well W has a casing 302 installed therein, casing 302 having tubing section 304 connected thereto. As is conventional, fluid communication is provided by placing holes in the tubing walls to allow gas to flow into the expander. Apparatus 300 includes a rotary pump 312. Rotary pump 312 includes an inlet end 314 and a discharge end 316. Rotary pump 312 further includes at least one pump impeller 315 intermediate inlet end 314 and discharge end 316.

Apparatus 300 further includes a driver for driving the at least one pump rotary pump impeller 315; the driver being operatively connected to rotary pump 312, for example, by a shaft 336. In the embodiment depicted in FIG. 4, the driver comprises a gas-powered expander 318. As shown, gas-powered expander 318 has an inlet 320 and a discharge end 322. As such, apparatus 300 comprises a down hole expander pump. As may be appreciated by those skilled in the art, gas-powered expander 318 may be driven by high-pressure gas from a down hole gas production zone.

In another embodiment, gas-powered expander 318 may be driven by injected gas lift gas G. To permit the flow of gas G to enter and turn expander 318, tubing section 304 may be perforated/slotted, with plug 308 positioned between tubing 304 and casing 302 to inhibit the flow of gas G within the annulus defined by tubing 304 and casing 302. In one embodiment, the down hole gas production zone may be regulated with a surface-controlled flow-control mechanism (not shown). In another embodiment, the injected gas lift gas G may enter the gas-powered expander inlet 320 through a gas lift mandrel (not shown).

As may be appreciated, the rotational speed or rate of gas-powered expander 318 may be varied by adjusting the characteristics of the gas lift gas G. In one embodiment, expanded gas is exhausted to the discharge 322. In another embodiment, the expanded gas is exhausted to a conduit (not shown) to the surface.

In one form, apparatus 300 may include an auger/charge pump assembly 360. Auger/charge pump assembly 360 serves to direct fluid into the inlet end 314 of rotary pump 312, preventing fluids from being blocked from entering due to high impeller speed.

As shown in FIG. 4, apparatus 300 further includes a magnetic bearing system 326, which may include a first bearing set 340 and a second bearing set 342. Magnetic bearing system 326 may be operatively connected to rotary pump 312 and/or gas-powered expander 318. In one embodiment, first bearing set 340 and second bearing set 342 may be spaced along shaft 336 for proper support. In one embodiment, magnetic bearing system 326 may be canned to prevent encroachment of wellbore fluids and improve reliability. A thrust bearing 338 may also included.

Apparatus 300 may also include magnetic bearing electronic controls 328, comprising a digital controller, and may also include subsurface monitoring instrumentation components 330. In one form, the digital controller of magnetic bearing electronic controls 328 is positioned within the wellbore to control the magnetic bearing system. As shown in FIG. 4, electronic controls 328 and/or subsurface monitoring components 330 are cooled with gas G at the discharge end of gas-powered expander 322. To power electronic controls 328 and instrumentation components 330, a generator 332 may be provided for converting a portion of the rotational energy of apparatus 300 to electrical power. In one embodiment, magnetic bearing system 326 is powered and controlled by the power produced by generator 332.

In one embodiment, the gas-powered expander 318 is connected to the rotary pump 312 by a magnetic gear 344. The term “magnetic gear” is used herein to refer to any change speed gearbox in which an input shaft is coupled magnetically for rotation with an output shaft, without the need for any physical contact between the two, the torque driving the output shaft being magnetically generated. Such a gearbox comprises an input shaft and a concentric output shaft both of which carry an array of permanent magnets. The two arrays of magnets are separated from one another by an intermediate ring comprising an array of pole pieces. The geometry of the permanent magnets and pole pieces determines the gearing ratio. Because an air gap exists between the pole pieces and the two arrays of permanent magnets, the internal parts of a magnetic gearbox do not require lubrication.

Advantageously, magnetic gear 344 may be used to generate electricity for onboard use. In one embodiment, gas-powered expander 318 operates at the same rotational speed or rate as rotary pump 312.

In one embodiment, subsurface monitoring instrumentation components 330 include onboard sensors and a portion of the electricity generated by apparatus 300 powers the onboard sensors. In another embodiment, the onboard sensors are used for closed-loop control of rotary pump 312.

Still referring to FIG. 4, the ability to provide wireless communications to the surface may be provided. In this regard a wireless communications card 350 may be provided. In one embodiment, electricity generated by converting a portion of the rotational energy of apparatus 300 may be used to power wireless communication card 350.

Referring now to FIG. 5, a schematic view of an illustrative, non-exclusive example of an apparatus 400 for removing fluids from a well W is shown. As is conventional, well W has a casing 402 installed therein, casing 402 having a tubing section 404 connected thereto. As is conventional, fluid communication is provided by placing holes in the tubing walls to allow gas to flow into the expander. Apparatus 400 includes a rotary pump 412. Rotary pump 412 includes an inlet end 414 and a discharge end 416. Rotary pump 412 further includes at least one pump impeller 415 intermediate inlet end 414 and discharge end 416.

Apparatus 400 further includes a driver for driving the at least one pump rotary pump impeller 415; the driver being positioned within the wellbore and operatively connected to rotary pump 412, for example, by a shaft 436. In the embodiment depicted in FIG. 5, the driver comprises an electric motor 418. As shown, electric motor 418 has a first end 420 and a second end 422. Electric motor 418 may be a high speed electric motor. In one embodiment, electric motor 418 may be a canned, seal-less motor. In one embodiment, electric motor 418 may be magnetically coupled to rotary pump 412 using a magnetic coupler, such as a magnetic gear (not shown). As may be appreciated, electric motor 418 may also include a variable speed drive (not shown) to control the speed or rate of electric motor 418.

In one form, apparatus 400 may include an auger/charge pump assembly 460. Auger/charge pump assembly 460 serves to direct fluid into the inlet end 414 of rotary pump 412, preventing fluids from being blocked from entering due to high impeller speed.

As shown in FIG. 5, apparatus 400 further includes a magnetic bearing system 426, which may include a first bearing set 440 and a second bearing set 442. Magnetic bearing system 426 may be operatively connected to rotary pump 412 and/or electric motor 418. In one embodiment, first bearing set 440 and second bearing set 442 may be spaced along shaft 436 for proper support of the rotating components. In one embodiment, magnetic bearing system 426 may be canned to prevent encroachment of wellbore fluids and improve reliability. A thrust bearing (not shown) may also be included.

Apparatus 400 may also include magnetic bearing electronic controls 428, comprising a digital controller, and may also include subsurface monitoring instrumentation components 430. In one form, the digital controller of magnetic bearing electronic controls 428 is positioned within the wellbore to control the magnetic bearing system. To power electronic controls 428 and instrumentation components 430, a generator (not shown) may be provided for converting a portion of the rotational energy of apparatus 400 to electrical power. In one embodiment, magnetic bearing system 426 is powered and controlled by the power produced by the generator.

In one embodiment, electric motor 418 may be connected to the rotary pump 412 by a magnetic gear (not shown). Advantageously, when employed, the magnetic gear may be used to generate electricity for onboard use. In one embodiment, electric motor 418 operates at the same rotational speed or rate as rotary pump 412.

In one embodiment, subsurface monitoring instrumentation components 430 include onboard sensors and a portion of the electricity generated by apparatus 400 powers the onboard sensors. In another embodiment, the onboard sensors are used for closed-loop control of rotary pump 412.

Still referring to FIG. 5, the ability to provide wireless communications to the surface may be provided. In this regard a wireless communications card 450 may be provided. In one embodiment, electricity generated by converting a portion of the rotational energy of apparatus 400 may be used to power wireless communication card 450.

In one embodiment, an electric or fiber optic cable (not shown) may be run in conjunction with a deployment device to relay sensor and control information to the surface. In another embodiment, permanent sensors may be employed for incorporating into a completion to provide operational support. In another embodiment, one or more fluid control devices may be incorporated into a completion to provide an additional well control barrier. In another embodiment, Y-tool may be employed when the rotary pump is placed in the well.

As discussed above, the use of a high speed driver enables the apparatus to be reduced in size over conventional electric submersible pumps and the like. In one embodiment, the driver drives the rotary pump to a rate greater than about 7200 rpm or greater than about 10,000 rpm or greater than about 20,000 rpm.

In some embodiments the well is an inclined well and is in fluid communication with a subterranean reservoir that produces sufficient gas to foul, interrupt, or cause significant pump efficiency losses. In some embodiments, the subterranean reservoir is gas-dominated.

FIG. 6 presents a schematic view of an illustrative, non-exclusive example of an apparatus 500 for producing gas from a wellbore or, alternatively, injecting a fluid into a wellbore, according to the present disclosure. Apparatus 500 includes a rotary compressor 512 for positioning within the wellbore. Rotary compressor 512 includes an inlet end 514 and a discharge end 516. Rotary compressor 512 further includes at least one compressor stage 515 intermediate inlet end 514 and discharge end 516. As may be appreciated, FIG. 6 depicts the case where apparatus 500 is used for production. Should apparatus 500 be used for the injection of fluids into a wellbore, apparatus 500 may be rotated 180 degrees, as those skilled in the art would plainly recognize.

Apparatus 500 further includes a driver for driving the at least one compressor stage 515; the driver being positioned within the wellbore and operatively connected to rotary compressor 512. In the embodiment depicted in FIG. 6, the driver comprises a gas-powered expander 518. As shown, gas-powered expander 518 has an inlet 520 and a discharge end 524. As may be appreciated by those skilled in the art, gas-powered expander 518 may be driven by high-pressure gas from a down hole gas production zone. In one embodiment, the down hole gas production zone may be regulated with a surface-controlled flow-control mechanism (not shown).

In another embodiment, gas-powered expander 518 may be driven by injected gas lift gas G. The injected gas lift gas G enters the gas-powered expander inlet through a down hole gas lift mandrel 522. As may be appreciated, the rotational speed or rate of gas-powered expander 518 may be varied by adjusting the characteristics of the gas lift gas G. In one embodiment, expanded gas is exhausted to the pump discharge 516. In another embodiment, the expanded gas is exhausted to a conduit (not shown) to the surface.

As shown in FIG. 6, apparatus 500 further includes a magnetic bearing system 526. Magnetic bearing system 526 may be operatively connected to rotary compressor 512 and/or gas-powered expander 518. In one embodiment, magnetic bearing system 526 is canned to prevent encroachment of wellbore fluids and improve reliability.

In one embodiment, apparatus 500 includes magnetic bearing electronic controls 528, comprising a digital controller, and may also include subsurface monitoring components 530. In one embodiment, electronic controls 528 and/or subsurface monitoring components 530 are cooled with gas at the discharge end of gas-powered expander 524. In one form, the digital controller of magnetic bearing electronic controls 528 is positioned within the wellbore to control the magnetic bearing system. To power electronic components, a generator 532 for converting a portion of the rotational energy of apparatus 500 to electrical power may be provided. In one embodiment, magnetic bearing system 526 is powered and controlled by the power produced by generator 532.

In one embodiment, gas-powered expander 518 operates at the same rotational speed or rate as rotary pump 512.

Referring now to FIG. 7, a schematic view of another illustrative, non-exclusive example of an apparatus 600 for producing gas from a wellbore or, alternatively, injecting a fluid into a wellbore, according to the present disclosure. Apparatus 600 includes a rotary compressor 612 for positioning within a well. Rotary compressor 612 includes an inlet end 614 and a discharge end 616. Rotary compressor 612 further includes at least one compressor stage 615 intermediate inlet end 614 and discharge end 616.

In the embodiment depicted in FIG. 7, the driver for driving the at least one compressor stage 615 comprises an electric motor 618. As shown, electric motor 618 has a first end 620 and a second end 622. Electric motor 618 may be a high speed electric motor. In one embodiment, electric motor 618 may be a canned, seal-less motor. Advantageously, electric motor 618 may be magnetically coupled to rotary compressor 612 using a magnetic coupler 620. As may be appreciated, electric motor 618 may also include a variable speed drive (not shown) to control the speed or rate of electric motor 618.

As shown in FIG. 7, apparatus 600 further includes a magnetic bearing system 626. Magnetic bearing system 626 may be operatively connected to rotary compressor 612 and/or electric motor 618. In one embodiment, magnetic bearing system 626 is canned to prevent encroachment of wellbore fluids and improve reliability.

In one embodiment, apparatus 600 includes magnetic bearing electronic controls 628, comprising a digital controller, and may also include subsurface monitoring components 630. In one form, the digital controller of magnetic bearing electronic controls 628 is positioned within the wellbore to control the magnetic bearing system. To power electronic components, a generator 632 for converting a portion of the rotational energy of apparatus 600 to electrical power may be provided. In one embodiment, magnetic bearing system 626 is powered and controlled by the power produced by generator 632.

Referring now to FIG. 8, a schematic view of another illustrative, non-exclusive example of an apparatus 700 for producing gas from a wellbore or, alternatively, injecting a fluid into a wellbore, according to the present disclosure. Apparatus 700 includes a rotary compressor 712 for positioning within a well W. Rotary compressor 712 includes an inlet end 714 and a discharge end 716. Rotary compressor 712 further includes at least one compressor stage 715 intermediate inlet end 714 and discharge end 716.

In the embodiment depicted in FIG. 8, the driver for driving the at least one compressor stage 715 comprises a hydraulic motor 718, the hydraulic motor having a power fluid inlet 720 and a power fluid discharge 722. Hydraulic motor 718, has a source of power fluid D (not shown), the power fluid D provided to the power fluid inlet 720 from the surface, as shown in FIG. 3. In one embodiment, a surface power fluid pump is employed, with the speed or rate of hydraulic motor 718 controlled by the output of the power fluid pump.

Alternatively, power fluid D may be provided to hydraulic motor 718 from a high-pressure liquid-producing zone, as those skilled in the art will plainly understand. In such cases, the high-pressure liquid-producing zone can be regulated from a surface-controlled, flow-control mechanism. In one embodiment, the spent power fluid may be discharged with the pump fluid.

As shown in FIG. 8, apparatus 700 further includes a magnetic bearing system 726. Magnetic bearing system 726 may be operatively connected to rotary compressor 712 and/or hydraulic motor 718. In one embodiment, magnetic bearing system 726 is canned to prevent encroachment of wellbore fluids and improve reliability.

In one embodiment, apparatus 700 includes magnetic bearing electronic controls 728, comprising a digital controller, and may also include subsurface monitoring components 730. In one form, the digital controller of magnetic bearing electronic controls 728 is positioned within the wellbore to control the magnetic bearing system. To power electronic components, a generator 732 for converting a portion of the rotational energy of apparatus 700 to electrical power may be provided. In one embodiment, magnetic bearing system 726 is powered and controlled by the power produced by generator 732.

As used herein, the term “and/or” placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity. Multiple entities listed with “and/or” should be construed in the same manner, i.e., “one or more” of the entities so conjoined. Other entities may optionally be present other than the entities specifically identified by the “and/or” clause, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, a reference to “A and/or B,” when used in conjunction with open-ended language such as “comprising” may refer, in one embodiment, to A only (optionally including entities other than B); in another embodiment, to B only (optionally including entities other than A); in yet another embodiment, to both A and B (optionally including other entities). These entities may refer to elements, actions, structures, steps, operations, values, and the like.

As used herein, the phrase “at least one,” in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entity in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase “at least one” refers, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and/or B”) may refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities). In other words, the phrases “at least one,” “one or more,” and “and/or” are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions “at least one of A, B and C,” “at least one of A, B, or C,” “one or more of A, B, and C,” “one or more of A, B, or C” and “A, B, and/or C” may mean A alone, B alone, C alone, A and B together, A and C together, B and C together, A, B and C together, and optionally any of the above in combination with at least one other entity.

In the event that any patents, patent applications, or other references are incorporated by reference herein and define a term in a manner or are otherwise inconsistent with either the non-incorporated portion of the present disclosure or with any of the other incorporated references, the non-incorporated portion of the present disclosure shall control, and the term or incorporated disclosure therein shall only control with respect to the reference in which the term is defined and/or the incorporated disclosure was originally present.

As used herein the terms “adapted” and “configured” mean that the element, component, or other subject matter is designed and/or intended to perform a given function. Thus, the use of the terms “adapted” and “configured” should not be construed to mean that a given element, component, or other subject matter is simply “capable of” performing a given function but that the element, component, and/or other subject matter is specifically selected, created, implemented, utilized, programmed, and/or designed for the purpose of performing the function. It is also within the scope of the present disclosure that elements, components, and/or other recited subject matter that is recited as being adapted to perform a particular function may additionally or alternatively be described as being configured to perform that function, and vice versa.

INDUSTRIAL APPLICABILITY

The systems and methods disclosed herein are applicable to the oil and gas industry.

It is believed that the disclosure set forth above encompasses multiple distinct inventions with independent utility. While each of these inventions has been disclosed in its preferred form, the specific embodiments thereof as disclosed and illustrated herein are not to be considered in a limiting sense as numerous variations are possible. The subject matter of the inventions includes all novel and non-obvious combinations and subcombinations of the various elements, features, functions and/or properties disclosed herein. Similarly, where the claims recite “a” or “a first” element or the equivalent thereof, such claims should be understood to include incorporation of one or more such elements, neither requiring nor excluding two or more such elements.

It is believed that the following claims particularly point out certain combinations and subcombinations that are directed to one of the disclosed inventions and are novel and non-obvious. Inventions embodied in other combinations and subcombinations of features, functions, elements and/or properties may be claimed through amendment of the present claims or presentation of new claims in this or a related application. Such amended or new claims, whether they are directed to a different invention or directed to the same invention, whether different, broader, narrower, or equal in scope to the original claims, are also regarded as included within the subject matter of the inventions of the present disclosure. 

1. An apparatus for removing fluids from a well, the apparatus comprising: a) a rotary pump for positioning within the well, the rotary pump including an inlet end and a discharge end, the rotary pump comprising at least one pump impeller intermediate the inlet end and discharge end, the at least one pump impeller rotating at a rate greater than 3600 rpm; b) a driver for driving the at least one pump impeller to a rate greater than above 3600 rpm, the driver positioned within the wellbore and operatively connected to the rotary pump; c) a magnetic bearing system, the magnetic bearing system operatively connected to the rotary pump and/or driver; and d) a digital controller positioned within the wellbore to control the magnetic bearing system.
 2. The apparatus of claim 1, wherein the driver is selected from a gas-powered expander, an electric motor, a hydraulic motor and combinations thereof
 3. The apparatus of claim 2, wherein the driver is a gas-powered expander having an inlet and a discharge end, the gas-powered expander driven by high-pressure gas from a down hole gas production zone.
 4. The apparatus of claim 3, wherein the down hole gas production zone is regulated with a surface-controlled flow-control mechanism.
 5. The apparatus of claim 3, wherein the gas-powered expander is driven by injected gas lift gas.
 6. The apparatus of claim 5, wherein the injected gas lift gas enters the gas-powered expander inlet through a down hole gas lift mandrel.
 7. The apparatus of claim 5, wherein the rotational speed of the gas-powered expander is varied by adjusting characteristics of the gas lift gas.
 8. The apparatus of claim 3, wherein the expanded gas is exhausted to the pump discharge.
 9. The apparatus of claim 3, wherein the expanded gas is exhausted to a conduit to the surface.
 10. The apparatus of claim 2, further comprising additional electronic control and/or monitoring components, wherein the additional electronic control and/or monitoring components and the digital controller are cooled with gas at the discharge end of the gas-powered expander.
 11. The apparatus of claim 2, wherein the gas-powered expander operates at the same rotational speed as the rotary pump.
 12. The apparatus of claim 2, wherein the driver is an electric motor.
 13. The apparatus of claim 12, wherein the electric motor is a canned, seal-less motor.
 14. The apparatus of claim 13, wherein the electric motor is magnetically coupled to the rotary pump.
 15. The apparatus of claim 14, further comprising a variable speed drive to control the rate of the electric motor.
 16. The apparatus of claim 2, wherein the driver is a hydraulic motor, the hydraulic motor having a power fluid inlet and a power fluid discharge.
 17. The apparatus of claim 16, further comprising a source of power fluid, the power fluid provided to the power fluid inlet from the surface through a conduit.
 18. The apparatus of claim 17, further comprising a surface power fluid pump, wherein the rate of the hydraulic motor is controlled by the output of the surface power fluid pump.
 19. The apparatus of claim 17, wherein the power fluid is provided to the hydraulic motor from a high-pressure liquid-producing zone.
 20. The apparatus of claim 19, wherein the high-pressure liquid-producing zone is regulated from a surface-controlled, flow-control mechanism.
 21. The apparatus of claim 16, wherein spent power fluid is discharged with the pump fluid.
 22. The apparatus of claim 1, further comprising a generator for converting a portion of the rotational energy of the apparatus to electrical power.
 23. The apparatus of claim 22, wherein the magnetic bearing system is powered and controlled by the power produced by the generator.
 24. The apparatus of claim 23, wherein the magnetic bearing system is canned to prevent encroachment of wellbore fluids and improve reliability.
 25. The apparatus of claim 1, wherein the driver is connected to the rotary pump by a magnetic gear.
 26. The apparatus of claim 25, wherein the magnetic gear generates electricity for onboard use.
 27. The apparatus of claim 26, further comprising onboard sensors, wherein at least a portion of the electricity generated powers the onboard sensors.
 28. The apparatus of claim 27, wherein the onboard sensors are used for closed-loop control of the rotary pump.
 29. The apparatus of claim 26, wherein the electricity generated powers wireless communications.
 30. The apparatus of claim 1, further comprising an electric or fiber optic cable run in conjunction with a deployment device to relay sensor and control information to the surface.
 31. The apparatus of claim 1, further comprising permanent sensors for incorporating into a completion to provide operational support.
 32. The apparatus of claim 1, further comprising one or more fluid control devices for incorporating into a completion to provide an additional well control barrier.
 33. The apparatus of claim 1 further comprising a Y-tool, the Y-tool when the rotary pump is placed in the well.
 34. The apparatus of claim 1, wherein the driver drives the rotary pump to a rate greater than 7200 rpm.
 35. The apparatus of claim 1, wherein the driver drives the rotary pump to a rate greater than 10,000 rpm.
 36. The apparatus of claim 1, wherein the driver drives the rotary pump to a rate greater than 20,000 rpm.
 37. A method of removing fluids from a well, comprising: a) installing an apparatus in a wellbore, the apparatus comprising a rotary pump having an inlet end and a discharge end, the rotary pump including at least one pump impeller intermediate the inlet end and discharge end; a driver for driving the at least one pump impeller, the driver positioned within the wellbore and operatively connected to one end of the rotary pump; a magnetic bearing system, the magnetic bearing system operatively connected to the rotary pump and/or driver; and a digital controller positioned within the wellbore to control the magnetic bearing system; b) operating the apparatus at a rate greater than 3600 rpm; and c) removing fluids from the well.
 38. The method of claim 37, wherein the driver is selected from a gas-powered expander, an electric motor, a hydraulic motor and combinations thereof
 39. The method of claim 38, wherein the driver is a gas-powered expander having an inlet end and a discharge end.
 40. The method of claim 39, further comprising the step of providing high- pressure gas from a down hole gas production zone to drive the gas-powered expander.
 41. The method of claim 40, further comprising the step of regulating the down hole gas production zone with a surface-controlled flow-control mechanism.
 42. The method of claim 39, further comprising the step of injecting gas-lift gas.
 43. The method of claim 41, further comprising the step of controlling the rotational speed of the gas-powered expander by adjusting the characteristics of the gas-lift gas.
 44. The method of claim 38, wherein the driver is a canned, seal-less electric motor.
 45. The method of claim 44, further comprising the step of magnetically coupling the electric motor to the rotary pump.
 46. The method of claim 44, further comprising the step of controlling the rate of the electric motor using a variable speed drive.
 47. The method of claim 38, wherein the driver is a hydraulic motor, the hydraulic motor having a power fluid inlet and a power fluid discharge.
 48. The method of claim 47, further comprising the step of providing a source of power fluid to the power fluid inlet from the surface through a conduit.
 49. The method of claim 48, wherein the source of power fluid includes a surface power fluid pump.
 50. The method of claim 49, further comprising the step of controlling the rate of the hydraulic motor by the output of the surface power fluid pump.
 51. The method of claim 47, further comprising the step of providing a source of power fluid to the hydraulic motor from a high-pressure liquid-producing zone.
 52. The method of claim 51, further comprising the step of regulating the power fluid from the high-pressure liquid-producing zone from a surface-controlled, flow-control mechanism.
 53. The method of claim 37, further comprising the step of converting a portion of the rotational energy of the apparatus to electrical power.
 54. The method of claim 53, wherein the magnetic bearing system is powered and controlled by the power converted from rotational energy.
 55. The method of claim 54, wherein the magnetic bearing system is canned to prevent encroachment of wellbore fluids and improve reliability.
 56. The method of claim 37, further comprising connecting the driver to the rotary pump by a magnetic gear.
 57. The method of claim 56, further comprising the step of generating electricity for onboard use using the magnetic gear.
 58. The method of claim 57, wherein at least a portion of the electricity generated powers sensors onboard the apparatus.
 59. The method of claim 58, further comprising the step of using signals from the onboard sensors to provide closed-loop control of the rotary pump.
 60. The method of claim 37, wherein the driver drives the rotary pump to a rate greater than 7200 rpm.
 61. The method of claim 37, wherein the driver drives the rotary pump to a rate greater than 10,000 rpm.
 62. The method of claim 37, wherein the driver drives the rotary pump to a rate greater than 20,000 rpm.
 63. An apparatus for producing fluids from a wellbore or injecting a fluid into a wellbore, the apparatus comprising: a) a rotary compressor including an inlet end and a discharge end, the rotary compressor comprising at least one compressor stage intermediate the inlet end and discharge end, the at least one compressor stage rotating at a rate greater than 3600 rpm; b) a driver for driving the at least one compressor stage to a rate greater than 3600 rpm, the driver positioned within the wellbore and operatively connected to the rotary compressor; c) a magnetic bearing system, the magnetic bearing system operatively connected to the high speed compressor and/or driver; d) a digital controller positioned within the wellbore to control the magnetic bearing system.
 64. The apparatus of claim 63, wherein the driver is selected from a gas-powered expander, an electric motor, a hydraulic motor and combinations thereof
 65. The apparatus of claim 63, further comprising a generator for converting a portion of the rotational energy of the apparatus to electrical power.
 66. The apparatus of claim 63, wherein the driver is connected to the rotary compressor by a magnetic gear, the magnetic gear generating electricity for onboard use.
 67. The apparatus of claim 63, wherein the produced fluid is gas.
 68. The apparatus of claim 63, wherein the driver drives the rotary compressor to a rate greater than 10,000 rpm.
 69. The apparatus of claim 63, wherein the driver drives the rotary compressor to a rate greater than 100,000 rpm.
 70. A method of producing fluids from a wellbore or injecting a fluid into a wellbore, comprising: a) installing an apparatus in a wellbore, the apparatus comprising a rotary compressor including an inlet end and a discharge end, the rotary compressor comprising at least one compressor stage intermediate the inlet end and discharge end, the at least one compressor stage rotating at a rate greater than 3600 rpm; a driver for driving the at least one compressor stage, the driver positioned within the wellbore and operatively connected to one end of the rotary compressor; and a magnetic bearing system, the magnetic bearing system operatively connected to the rotary compressor and/or driver; and a digital controller positioned within the wellbore to control the magnetic bearing system; b) operating the apparatus at a rate greater than 3600 rpm; and c) removing fluids from the well.
 71. The method of claim 70, wherein the driver is selected from a gas-powered expander, an electric motor, a hydraulic motor and combinations thereof
 72. The method of claim 71, wherein the driver is a gas-powered expander having an inlet end and a discharge end.
 73. The method of claim 71, wherein the electric motor is magnetically coupled to the rotary compressor.
 74. The method of claim 70, wherein the driver is connected to the rotary compressor by a magnetic gear.
 75. The method of claim 74, further comprising the step of generating electricity for onboard use using the magnetic gear.
 76. The method of claim 75, wherein at least a portion of the electricity generated powers sensors onboard the apparatus.
 77. The method of claim 76, further comprising the step of using signals from the onboard sensors to provide closed-loop control of the rotary compressor.
 78. The method of claim 70, wherein the produced fluid is gas.
 79. The method of claim 70, wherein the driver drives the at least one compressor stage to a rate greater than 10,000 rpm.
 80. The method of claim 70, wherein the driver drives the at least one compressor stage to a rate greater than 100,000 rpm.
 81. A wellbore comprising: a) a borehole in fluid communication with a subterranean reservoir; b) an apparatus for removing or injecting fluids, the apparatus installed within the wellbore and comprising i) a rotary pump or rotary compressor, the rotary pump or rotary compressor including an inlet end and a discharge end, and at least one pump impeller or at least one intermediate compressor stage rotating at a rate greater than about 3600 rpm; ii) a driver for driving the at least one pump impeller or at least one intermediate compressor stage to a rate greater than above about 3600 rpm, the driver positioned within the wellbore and operatively connected to the rotary pump or rotary compressor; iii) a magnetic bearing system, the magnetic bearing system operatively connected to the rotary pump or rotary compressor and/or driver; and iv) a digital controller positioned within the wellbore to control the magnetic bearing system.
 82. The wellbore of claim 81, wherein the driver is selected from a gas-powered expander, an electric motor, a hydraulic motor and combinations thereof
 83. The wellbore of claim 81, wherein the apparatus comprises a rotary pump for the production of reservoir fluids.
 84. The wellbore of claim 81, wherein the apparatus comprises a rotary pump for the injection of fluids.
 85. The wellbore of claim 81, wherein the apparatus comprises a rotary pump for the separation of production fluids.
 86. The wellbore of claim 81, wherein the apparatus comprises a rotary compressor for enhancing fluid flow in a gas well.
 87. The wellbore of claim 81, wherein the apparatus comprises a rotary compressor for increasing the gas velocity in a production well. 